Standby/Capacity Reservation Charge Best Practices and Review: Prepared for Pennsylvania Public Utility Commission CHP Working Group April 16, 2019 By: EXERGY

Partners Corp.

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Acknowledgments We greatly appreciate the assistance of the following individuals in preparing and/or reviewing this report:

• Joseph M. Sherrick Supervisor Technical Utility Services, Policy & Planning, Pennsylvania Public Utility Commission

• Dr. James Freihaut, Director of DOE’s Mid-Atlantic CHP Technology Assistance Partnership • Vestal Tutterow, Laurence Berkley National Laboratory

We also acknowledge the rate review guidance provided by PECO, Duquesne Light and PPL.

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Background The Pennsylvania Public Utility Commission issued its Final Policy Statement on Combined Heat and Power April 5, 2018. The opening of the statement reads:

In light of the potential benefits to the public of Combined Heat and Power (CHP), the Commission is interested in considering ways to advance the development of CHP in Pennsylvania. The Commission recognizes that CHP is an efficient means of generating electric power and thermal energy from a single fuel source, providing cost effective energy services to commercial businesses like hotels, universities and hospitals. CHP systems capture the waste heat energy that is typically lost through power generation, using it to provide heating and cooling for manufacturing and business. In addition to improving manufacturing competitiveness and reducing greenhouse gas emissions, CHP benefits businesses by reducing energy costs and enhancing reliability for the user. The Commission observes that there are several areas where electric and natural gas distribution companies (EDCs and NGDCs) may be able to implement policies and practices that reduce barriers to such development. With this Order, the Commission establishes a biennial reporting requirement for EDCs and NGDCs regarding their efforts to eliminate obstacles to the development of CHP in the Commonwealth.

National Association of Regulatory Utility Commissioners Board of Directors issued the following resolution actions February 13, 2019:

Now therefore be it resolved that the Board of Directors of the National Association of Regulatory Utility Commissioners, convened at its 2019 Winter Meeting in Washington, D.C., supports further discussion relating to the setting of standby rates for partial requirements customers that affect market entry and continued competitiveness of distributed generation; encourages regulators to consider whether the cost of standby rates discourages further deployment of CHP and WHP, and could harm CHP and WHP facility competitiveness; and encourages Commissioners to assure that standby rates for partial requirements customers acknowledge that: (a) effectively coordinating CHP and WHP with grid system operations reduces demand and costs; and (b) CHP and WHP have the potential to improve system reliability and resiliency.

Purpose of this Analysis Standby tariffs and rates can affect the economic feasibility of CHP projects. Customers who receive all of their electricity from the utility are known as “full requirements” customers. Their electricity is provided under rates that are primarily some mix of fixed customer charges - a recurring charge (monthly or daily) intended to cover the constant costs of metering, billing, and service drop facilities; energy charges - the charges for consumption of the electricity commodity applied on a per-kWh basis; and demand charges – charges based on the peak electricity demand (kW) during a given period and used to recover the capital costs of the capacity necessary to meet the customer’s peak loads. Customers with onsite generation typically require a different set of services, which includes continuing electricity service for the portion of usage that is not provided by the onsite generator, as well as service for periods of scheduled or unscheduled outages. “Partial requirements” is the more precise name for standby or backup service: the set of retail electric products that customers with onsite, non-emergency generation typically need. This service could be provided under a tariff that replaces the standard full requirements tariff, or an additional tariff that applies on top of the

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standard tariff for certain special types of services. Common components of service for partial requirements customers can include:

(1) Supplemental Service. Supplemental service for customers whose on-site generation does not meet all of the customer’s needs. In many cases, it is provided under the otherwise applicable full requirements tariff.

(2) Back-up Service. Back-up, or stand-by, serves a customer’s load that would otherwise be served by DG, during unscheduled outages of the on-site generation.

(3) Scheduled Maintenance Service. Scheduled maintenance service is taken when the customer’s generator is due to be out of service for routine maintenance and repairs.

(4) A capacity reservation charge to compensate the utility for the capacity that the utility must have available to serve a customer during an unscheduled outage of the customers own generation unit.

This analysis was undertaken to support the PA PUC’s CHP working group to better understand the nature of standby, reservation charge and supplemental charges in Pennsylvania and the impact of these charges on CHP project economics. 5-Lakes Energy was initially engaged to gather the relevant rate data from three EDCs - PECO, PPL and Duquesne - and develop a model to assess the annual electricity costs for three CHP use cases detailed later in this report. 5-Lakes later became involved in an ongoing EDC rate case and did not participate in subsequent direct EDC contact or further analysis based on feedback from the EDCs. Exergy Partners Corp. and Entropy Research LLC worked with PECO, PPL and Duquesne to improve the accuracy of the modeling within current time constraints to be sure the relative comparisons are as accurate as possible. It should be noted that the three EDCs were cooperative in preparing this report to aid in discussion during the PA PUC CHP Working Group. At this time, we have analysis of the impact PECO’s standby Capacity Reserve Rider “CRR” and Duquesne’s standby Rider 16. Time did not permit the same level of analysis regarding PPL’s standby Rider 6.

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Standby/Reservation Charges To better understand the nature and structure of Electric Distribution Companies (EDCs) standby, Penn State University contracted with 5-Lakes Energy to initially examine standby charges impacting three typical CHP systems types and applications1: 1. 8 MW combustion turbine CHP system used in a high load factor production facility - 24/7 operation

Figure 1: High Load Factor Production Load Profile

Figure 2: High Load Factor Production CHP Dataset Example

CHP system assumptions: CHP Capacity: 8 MW CHP Electrical Efficiency: 29.2% Useful Thermal: 4,848 Btu/kWh CHP O&M cost: 0.012 $/kWh Fuel Price, $/MMBtu: $5.00 CHP operation: 24 hours/day, 7 days/week Scheduled Maintenance Outage: One 10-day outage in January Unscheduled Forced Outage: One 24-hour outage in July

1 For comparison purposes a natural gas price of $5 / MMBtu was used in all cases for CHP prime mover fuel and displaced boiler fuel costs

Base Voltage: 13,200Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Bil l ing days per month 31 28 31 30 31 30 31 31 30 31 30 31 365

Hours 744 672 744 720 744 720 744 744 720 744 720 744 8760Maximum Demand, kW 9,685 9,691 9,754 9,939 11,454 12,000 11,992 11,874 11,898 9,939 9,872 9,845 12,000

Average Demand, kW 8,988 8,978 8,976 9,017 10,173 10,363 10,556 10,512 10,411 9,034 9,015 9,011 9,590Minimum Demand, kW 8,659 8,659 8,659 8,659 9,238 9,454 9,851 9,889 9,712 8,659 8,659 8,659 8,659

Consumption, kWh 6,687,328 6,033,316 6,678,317 6,492,359 7,568,346 7,461,397 7,853,748 7,821,226 7,496,206 6,721,619 6,490,696 6,704,248 84,008,805CHP Generation, kWh 4,040,000 5,376,000 5,952,000 5,760,000 5,952,000 5,760,000 5,760,000 5,952,000 5,760,000 5,952,000 5,760,000 5,952,000 67,976,000

Standby Generation kWh 1,912,000 0 0 0 0 0 192,000 0 0 0 0 0 2,104,000Supplemental Generation kWh 735,328 657,316 726,317 732,359 1,616,346 1,701,397 1,901,748 1,869,226 1,736,206 769,619 730,696 752,248 13,928,805 #

Max Supplemental Demand kW 1,685 1,691 1,754 1,939 3,454 4,000 3,992 3,874 3,898 1,939 1,872 1,845 4,000Average Supplemental Demand kW 988 978 976 1017 2173 2363 2556 2512 2411 1034 1015 1011 1586

Load Factor 0.799

Application: High Load Factor Production - 24/7 Oper

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2. 1 MW reciprocating engine CHP system in an average load factor production facility - 2 shifts/5 days per week operation

Figure 3: Average Load Factor Production Load Profile

Figure 4: Average Load Factor Production CHP Dataset Example

CHP system assumptions: CHP Capacity: 1 MW CHP Electrical Efficiency: 37.6% Useful Thermal: 3,909 Btu/kWh CHP O&M cost: 0.011 $/kWh Fuel Price, $/MMBtu: $5.00 CHP operation: 18 hours/day, 5 weekdays/week Scheduled Maintenance Outage: One 36-hour weekend outage in January Unscheduled Forced Outage: Two 18-hour weekday outages in February and July

Base Voltage: 13,200/4,160Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Bil l ing days per month 31 28 31 30 31 30 31 31 30 31 30 31 365Hours 744 672 744 720 744 720 744 744 720 744 720 744 8,760

Maximum Demand, kW 1,311 1,318 1,363 1,418 1,656 1,747 1,750 1,723 1,726 1,418 1,401 1,394 1,750Average Demand Op Hours, kW 1,079 1,080 1,075 1,162 1,384 1,450 1,474 1,399 1,456 1,160 1,126 1,152 1,250

Average Demand, kW 760 761 758 804 976 1,036 1,081 1,044 1,052 803 785 799 889Minimum Demand, kW 357 357 357 357 471 524 593 598 551 357 357 357 357

Consumption, kWh 565,565 511,189 564,035 579,036 726,320 746,125 804,061 776,422 757,465 597,739 565,336 594,669 7,787,962CHP Generation, kWh 361,479 341,014 397,479 384,658 397,479 384,658 379,479 397,479 384,658 397,479 384,658 397,479 4,608,000

Standby Generation kWh 36,000 18,000 0 0 0 0 18,000 0 0 0 0 0 72,000Supplemental Generation kWh 168,085 152,175 166,556 194,378 328,840 361,467 406,582 378,943 372,808 200,260 180,678 197,190 3,107,962 #

Max Supplemental Demand kW 432 432 432 432 656 747 750 723 726 432 432 432 750Average Supplemental Demand kW 226 226 224 270 442 502 546 509 518 269 251 265 354

Load Factor 0.508

Application: Average Load Factor Production - 2 Shifts/5 Days per Week Oper

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3. 200 kW microturbine CHP system in an office building with normal business hour operation

Figure 5: Office Building with Normal Business Hour Operation Load Profile

Figure 6: Office Building with Normal Business Hour Operation CHP Dataset Example

CHP system assumptions: CHP Capacity: 200 kW CHP Electrical Efficiency: 28.4% Useful Thermal: 4,578 Btu/kWh CHP O&M cost: 0.02 $/kWh Fuel Price, $/MMBtu: $5.00 CHP operation: 12 hours/day, 5 weekdays/week Scheduled Maintenance Outage: One 5 weekday outage in January Unscheduled Forced Outage: One 12-hour weekday outage in July

Base Voltage: 480Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Bil l ing days per month 31 28 31 30 31 30 31 31 30 31 30 31 365Hours 744 672 744 720 744 720 744 744 720 744 720 744 8,760

Maximum Demand, kW 226 231 221 276 308 348 350 339 338 283 204 204 350Average Demand Op Hours, kW 216 219 198 256 287 301 308 290 305 244 190 198 251

Average Demand, kW 135 136 129 164 191 202 212 207 207 175 126 129 168Minimum Demand, kW 78 78 78 100 125 136 146 149 140 125 78 78 78

Consumption, kWh 100,422 91,442 95,734 117,795 141,884 145,750 157,623 154,011 149,040 130,396 90,602 95,754 1,470,454CHP Generation, kWh 40,997 47,868 52,997 51,288 52,997 51,288 50,597 52,997 51,288 52,997 51,288 52,997 609,600

Standby Generation kWh 12,000 0 0 0 0 0 0 2,400 0 0 0 0 14,400Supplemental Generation kWh 47,424 43,574 42,736 66,508 88,887 94,463 107,026 98,614 97,753 77,398 39,314 42,757 846,454 #

Max Supplemental Demand kW 103 103 103 125 150 161 171 174 165 150 103 103 174Average Supplemental Demand kW 64 65 57 92 119 131 144 133 136 104 55 57 96

Load Factor 0.479

Application: Office Building - Normal Business Hrs Oper

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Results PECO The CRR applies to parallel-generating customers to commercial and industrial customers placing generation facilities with over 100 kW nameplate capacity online on or after 1/1/2016. The CRR modifies customer’s minimum billing demand. Min Billing Demand Under CRR = Min Billing Demand Under Prevailing Tariff Rate (40% of uncovered demand2) + “CRR Level” applying to customer’s generation nameplate as follows: > 100 kW but <= 5,000 kW – 60% of generator nameplate rating > 5,000 kW but <= 10,000 kW – 50% of generator nameplate rating > 10,000 kW – Determined by negotiation (not < 40%) Amount of reserved capacity reflects potential peak demand For example:

Figures 7 to 9 show the calculated Transmission, Standby/Reservation Charges & Supplemental electric cost for the three case studies both with and without PECO’s Capacity Reserve Rider. The model used 2018 PECO’s High-Tension Rate Tariff for the 12,000 kW and 1,750 kW sites and PECO’s General Service Rate Tariff for the 350 kW site. Note the CRR does not distinguish between planned maintenance outages or unplanned outages. Figures 7 through 9 show that for all three cases, using the CRR is more costly than the standard rate tariff for the three defined typical CHP cases.

Table 1 PECO 2018 High Tension Rate Tariff Electricity Cost in the Model for the 12,000 kW and 1,750 kW Case Studies

2 any load behind meter not covered by CRR e.g. annual peak load minus CHP unit electric capacity covered by the CRR

Energy Supply Charge Rate $0.030206 per kWhRate administrative adder $0.004860 per kWhEnergy Capacity Charge Rate $0.1537 per kWVariable Distribution Service Charge Rate $4.77 per kW

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Table 2 PECO 2018 General Service Rate Tariff Electricity Cost in the Model for the 350 kW Case Study

Figure 7: PECO Transmission, Standby/Reservation Charges & Supplemental 12 MW Site - 8 MW CHP

Figure 8: PECO Transmission, Standby/Reservation Charges & Supplemental 1.75 MW Site - 1 MW CHP

Energy Supply Charge Rate $0.030206 per kWhRate administrative adder $0.005060 per kWhEnergy Capacity Charge Rate $0.1537 per kWVariable Distribution Service Charge Rate $7.98 per kW

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Figure 9: PECO Transmission, Standby/Reservation Charges & Supplemental 350 kW Site - 200 kW CHP

Understanding the impact of the base rate tariff versus the CRR rate tariff has on the three cases studies. The impact on purchased electricity costs switching between the two tariffs has on the CHP system operation can be seen in the second column of Table 3 Total Purchased Electricity. The last column in Table 3 shows the impact of not using the CRR. In the case of the 8,000-kW CHP system, by not using the CRR you gain $45,431 in annual savings, in the case of the 1,000-kw system you gain $10,813 annually and the 200-kW system you gain $3,792 annually. Note the largest percentage differential between the CRR rate and the base tariff is in the 200 kW CHP case.

Table 3: PECO Operating Costs and CHP Savings with and without CRR

PECO HT with CRR 8,000 kW $1,273,468 $3,971,475 $815,712 ($2,059,673) $4,000,982 $4,528,162 $527,180

PECO HT without CRR 8,000 kW $1,228,037 $3,971,475 $815,712 ($2,059,673) $3,955,551 $4,528,162 $572,611 $45,431

PECO HT with CRR 1,000 kW $233,255 $209,076 $87,552 ($112,579) $417,304 $499,635 $82,331

PECO HT without CRR 1,000 kW $222,443 $209,076 $87,552 ($112,579) $406,491 $499,635 $93,143 $10,813

PECO GS with CRR 200 kW $70,327 $36,619 $12,192 ($17,442) $101,696 $106,925 $5,229

PECO GS without CRR 200 kW $66,535 $36,619 $12,192 ($17,442) $97,904 $106,925 $9,021 $3,792

Savings without CRR

Total Operating Cost with CHP

Total Purchased Electricity

Total Operating Cost without

CHP

Operating Cost Savings with

CHP

CHP Capacity Case

CHP Fuel Cost CHP O&MDisplaced Boiler

Fuel

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Duquesne Power and Light Figures 10 to 12 show the calculated Transmission, Standby/Reservation Charges & Supplemental electric cost for the three case studies both with and without Duquesne’s Rider 16. Rider 16 states that a distribution charge of $2.50 per kW shall be applied to the Back-Up Power Billing Determinants for Back-Up Power. The distribution charges will be applied in each month based on the customer’s Contract Demand without regard to whether or not back-up energy is supplied. Note that Rider 16 does not distinguish between planned maintenance outages or unplanned outages. Figures 10 through 12 show that for all three cases, using the Rider 16 is less costly than the standard rate tariff. Rider 16 clearly shows that outage energy, demand and reservation charges combined with the reduced distribution capacity charge is less than the distribution capacity charge using the conventional rate tariff. In this case, Rider 16 performs as expected, reducing the cost for all three defined typical CHP cases. Table 4-6 show the base rates for the three cases used in the model.

Table 4 Duquesne Large Rate Tariff Electricity Cost in the Model for the 8,000 kW Case Study

Table 5 Duquesne General Service Large Rate Tariff Electricity Cost in the Model for the 1,000 kW Case Study

Table 6 Duquesne General Service Small and Medium Rate Tariff Electricity Cost in the Model for the 350 kW Case Study

Rate administrative adder $0.001740 per kWhEnergy Capacity Charge Rate (per kW) $0.15361 per kWVariable Distribution Service Charge Rate $13.12 per kWTransmission Service Charge Rate $4.10 per kW

Rate administrative adder $0.001740 per kWhEnergy Capacity Charge Rate (per kW) $0.15361 per kWVariable Distribution Service Charge Rate $8.41 per kWTransmission Service Charge Rate $3.95 per kW

Rate administrative adder $0.001740 per kWhEnergy Capacity Charge Rate (per kW) $0.15361 per kWVariable Distribution Service Charge Rate $6.54 per kWTransmission Service Charge Rate $1.77 per kW

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Figure 10: Duquesne Transmission, Standby/Reservation Charges & Supplemental 12 MW Site - 8 MW CHP

Figure 11: Duquesne Transmission, Standby/Reservation Charges & Supplemental 1.75 MW Site - 1 MW CHP

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Figure 12: Duquesne Transmission, Standby/Reservation Charges & Supplemental 350 kW Site - 200 kW CHP

Table 8 shows the impact of the of Duquesne’s rate tariffs on the three CHP cases. Understanding the impact of the base rate tariff versus the CRR rate tariff has on the three cases studies. The impact on purchased electricity costs switching between the two tariffs has on the CHP system operation can be seen in the second column of Table 3 Total Purchased Electricity. The last column in Table 3 shows the impact of using the Rider 16. In the case of the 8,000-kW CHP system, by using the Rider 16 you gain $974,860 in annual savings, in the case of the 1,000-kw system you gain $62,814 annually and the 200-kW system you gain $8,511 annually. Note the largest percentage differential between Ricer 16 and the base tariff is in the 8,000 kW CHP case moving from a loss to a significant gain. Note the large impact in the 8,000 kW CHP case.

Table 7: Duquesne Operating Costs and CHP Savings with and without Rider 16

Duquesne Rider 16 8,000 kW $1,857,126 $3,971,475 $815,712 ($2,059,673) $4,584,640 $5,284,991 $700,351 $974,860

Duquesne Rider GL 8,000 kW $2,831,986 $3,971,475 $815,712 ($2,059,673) $5,559,500 $5,284,991 ($274,508)

Duquesne Rider 16 1,000 kW $336,079 $209,076 $87,552 ($112,579) $520,127 $595,549 $75,422 $62,814

Duquesne Rider GL 1,000 kW $398,893 $209,076 $87,552 ($112,579) $582,941 $595,549 $12,608

Duquesne Rider 16 200 kW $68,288 $36,619 $12,192 ($17,442) $99,657 $114,862 $15,205 $8,511

Duquesne Rider GS 200 kW $74,240 $36,619 $12,192 ($17,442) $105,609 $112,303 $6,694

Savings with Rider 16

Total Purchased Electricity

CHP Fuel Cost CHP O&MDisplaced Boiler

FuelCHP Capacity

Case

Total Operating Cost without

CHP

Total Operating Cost with CHP

Operating Cost Savings with

CHP

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Findings The analysis raises a series of question regarding standby rate complexity, transparency and equity. 1. There appears to be little consistency between the EDCs with respect to standby charges. 2. Standby / Reservations charges and structure vary considerably between the three EDCs. 3. Descriptors vary widely for services, which fosters confusion. 4. PECO’s CRR standby rate had a negative impact on the three CHP cases reviewed. 5. Duquesne’s Rider 16 standby rate had a positive impact on the three CHP cases reviewed. 6. Tariffs descriptions were sometimes not clear – providing example calculations would help (one EDC

had one example calculation). 7. Structures can be complex and difficult to properly apply without utility input. One example of utility

assistance is from Ameren Missouri Rates group which has developed excel tools which customers can use to input projected load profiles and generation assumptions to estimate the impact of standby rider on their bill. https://www.ameren.com/missouri/business/rates/electric-rates/rider-ssr

8. There was no distinction between maintenance backup power (which can often be scheduled off-peak) demand and unscheduled downtime.

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General Recommendation for Standby and Reservation Charges3 Summary of Best Practices in Standby Rate Design Based on the experience of RAP and BAI in the area of standby rate design, explained in Chapter 1, the following are best practices for consideration in the development of standby rates: Allocation of Utility Costs

• Generation, transmission, and distribution charges should be unbundled in order to provide transparency to customers and enable appropriate and cost-based standby rate design.

• Supplemental power charges should be based on charges in the applicable full requirements tariff.

• Generation reservation demand charges should be based on the utility’s cost and the forced outage rate of customers’ generators on the utility’s system.

Judgments Based on Statistical Method

• Standby rate design should not assume that all forced outages of on-site generators occur simultaneously, or at the time of the utility system peak.

• Transmission and higher-voltage distribution demand charges should be designed in a manner that recognizes load diversity.

• Standby rate design should assume that maintenance outages of on-site generators would be coordinated with the utility and scheduled during periods when system generation requirements are low.

Value of Customer Choice and Incentives

• Daily maintenance demand charges should be discounted relative to daily backup demand charges to recognize the scheduling of maintenance service during periods when the utility generation requirements are low.

• Customers should have the option to purchase all or some portion of their standby service on an interruptible basis and thereby avoid generation reservation demand charges.

• Pro-rated, daily, as-used demand charges for backup power and shared transmission and distribution facilities should be used to provide an incentive for generator reliability.

• Customers should be able to procure standby service from competitive power providers at prevailing market prices, where available.

3 Standby Rates for Combined Heat and Power Systems Economic Analysis and Recommendations for Five States, James Selecky, Kathryn Iverson, and Ali Al-Jabir, Regulatory Assistance Project, February 2014

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Why not use 2019 resolution? Appendix A: NARUC Resolution on Standby Rates for Partial Requirements Customers Whereas the National Association of Regulatory Utility Commissioners (“NARUC”) and its members have long focused on energy efficiency, electric system reliability and resiliency, and reduction of greenhouse gas emissions; Whereas combined heat and power (“CHP”) can be a cost-effective way to produce two or more forms of useful energy from a single fuel source, often including both thermal energy and electricity; Whereas waste heat to power (“WHP”) is the process of capturing heat discarded by an existing process and using that heat to generate power with no additional fuel, combustion or emissions; Whereas CHP and WHP are forms of distributed generation that can provide benefits for consumers and to U.S. businesses in the form of reduced energy costs, reduced risk of electric grid disruption and enhanced energy reliability, stability, and resilience in the face of uncertain electricity prices and major disruptive events; Whereas CHP and WHP can provide benefits for the nation by lowering the need for other, less efficient sources of new electric generation capacity, avoiding transmission and distribution costs, creating markets for domestic energy sources, developing and maintaining employment opportunities for skilled labor, optimizing the use of our nation’s abundant supply of natural gas, and reducing emissions; Whereas CHP can provide services in a microgrid in ways that can help enable better use of other clean energy sources; Whereas federal law recognizes these benefits by affording Qualifying Facility status to CHP and WHP systems and the executive branch in 2012 established a national goal of increasing CHP deployment by approximately 50% by 2020; Whereas in 2008 NARUC passed a resolution explicitly urging commissions to “consider the adoption of regulatory policies that protect consumers while addressing barriers to increased use of CHP related to standby rate design;” Whereas in 2012 NARUC passed a resolution encouraging State public service commissions to evaluate opportunities for CHP, encourage cost effective investment in CHP, and evaluate regulatory mechanisms to best deploy these technologies; Whereas in 2013 NARUC passed a resolution supporting the inclusion of WHP technologies in State and federal clean energy policies and programs; Whereas despite these resolutions and the widespread recognition of these benefits, the technical and economic potential for CHP and WHP far exceeds their deployment; Whereas many utility companies have “standby” rates for customers taking “partial-requirements service” that may be confusing, might not be based on cost-of-service principles, and may fail to account for the benefits that these systems offer to the grid;

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Whereas the NARUC Distributed Energy Resources Rate Design and Compensation manual provides that standby rates should reflect actual system costs and clarifies that charges should not discourage investment in CHP by potential customers; Whereas encouraging or requiring CHP or WHP hosts to schedule maintenance during off-peak times and distinguishing between scheduled and unscheduled outages can reduce utility system demand and costs; Whereas the rates for partial requirements service should be as simple, transparent, and consistent as practical; Now therefore be it resolved that the Board of Directors of the National Association of Regulatory Utility Commissioners, convened at its 2019 Winter Meeting in Washington, D.C., supports further discussion relating to the setting of standby rates for partial requirements customers that affect market entry and continued competitiveness of distributed generation; encourages regulators to consider whether the cost of standby rates discourages further deployment of CHP and WHP, and could harm CHP and WHP facility competitiveness; and encourages Commissioners to assure that standby rates for partial requirements customers acknowledge that: (a) effectively coordinating CHP and WHP with grid system operations reduces demand and costs; and (b) CHP and WHP have the potential to improve system reliability and resiliency. _________________________________ Sponsored by the Committee on Energy Resources and the Environment Adopted by the NARUC Board of Directors on February 13, 2019

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Appendix B: PECO Capacity Reserve Rider

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• Appendix C: Duquesne Rider 16

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Appendix D: Ameren Missouri Rider SSR - Standby Service Rider